A choke valve is a throttling device. It is commonly used as part of an oil or gas field wellhead. It functions to reduce the pressure of the fluid flowing through the valve. Choke valves are placed on the production “tree” of an oil or gas wellhead assembly to control the flow of produced fluid from a reservoir into the production flow line. They are used on wellheads located on land and offshore, as well as on wellheads located beneath the surface of the ocean.
Choke valves common to oil and gas field use are generally described in U.S. Pat. No. 4,540,022, issued Sep. 10, 1985, to Cove and U.S. Pat. No. 5,431,188, issued Jul. 11, 1995 to Cove. Both patents are commonly owned by Master Flo Valve, Inc., the assignee of the present application.
In general, chokes involve:
a valve body having an axial bore, a body inlet (typically referred to as a side outlet) and a body outlet (typically referred to as an end outlet);
a “flow trim” mounted in the bore between inlet and outlet, for throttling the flow moving through the body; and
means for actuating the flow trim, said means closing the end of the bore remote from the outlet.
There are four main types of flow trim commonly used in commercial chokes. Each flow trim involves a port-defining member, a movable member for throttling the port, and seal means for implementing a total shut-off. These four types of flow trim can be characterized as follows:
(1) a needle-and-seat flow trim comprising a tapered annular seat fixed in the valve body and a movable tapered internal plug for throttling and sealing in conjunction with the seat surface;
(2) a cage-with-internal-plug flow trim, comprising a tubular, cylindrical cage, fixed in the valve body and having ports in its side wall, and a plug movable axially through the bore of the cage to open or close the ports. Shut-off is generally accomplished with a taper on the leading edge of the plug, which seats on a taper carried by the cage or body downstream of the ports;
(3) a multiple-port-disc flow trim, having a fixed ported disc mounted in the valve body and a rotatable ported disc, contiguous therewith, that can be turned to cause the two sets of ports to move into or out of register, for throttling and shut-off; and
(4) a cage-with-external-sleeve flow trim, comprising a tubular cylindrical cage having ports in its side wall and a hollow cylindrical sleeve that slides axially over the cage to open and close the ports. The shut-off is accomplished with the leading edge of the sleeve contacting an annular seat carried by the valve body or cage.
In each of the above, the flow trim is positioned within the choke valve at the intersection of the choke valve's inlet and outlet. In most of the valves, the flow trim includes a stationary tubular cylinder referred to as a “cage”, positioned transverse to the inlet and having its bore axially aligned with the outlet. The cage has restrictive flow ports extending through its sidewall. Fluid enters the cage from the choke valve inlet, passes through the ports and changes direction to leave the cage bore through the valve outlet.
Such a flow trim also includes a tubular throttling sleeve that slides over the cage. The sleeve acts to reduce or increase the area of the ports. An actuator, such as a threaded stem assembly, is provided to bias the sleeve back and forth along the cage. The rate that fluid passes through the flow trim is dependent on the relative position of the sleeve on the cage and the amount of port area that is revealed by the sleeve.
Maintenance on the deep sub-sea wellhead assemblies cannot be performed manually. An unmanned, remotely operated vehicle, referred to as an “ROV”, is used to approach the wellhead and carry out maintenance functions. To aid in servicing sub-sea choke valves, choke valves have their internal components, including the flow trim, assembled into a modular sub-assembly. The sub-assembly is referred to as an “insert assembly” and is inserted into the choke valve body and clamped into position.
A typical prior art sub-sea choke valve 1 is shown in FIG. 1. It comprises a choke body 2 forming a T-shaped bore 3 that provides a horizontal inlet 4 (body inlet), a vertical bottom outlet 5 (body outlet) and an upper vertical component chamber 6 (insert chamber). A removable insert assembly 7 is positioned in the component chamber 6, extending transversely of the inlet 4. The insert assembly 7 includes a tubular cartridge 8, forming a side port 9, a flow trim 10 including a cage 11 and throttling sleeve 12, a collar assembly 13 and a bonnet 14. The bonnet 14 is disengagably clamped to the valve body 2. It closes the upper ends of the valve body 2 and the cartridge 8. The collar assembly 13 extends through the bonnet 14 into the cartridge bore 15 to bias the sleeve 12 along the cage 11 to throttle the restrictive flow ports 16.
The choke valve “sees” or experiences relatively high and relatively low fluid pressures. More particularly, the fluid flowing in through the valve body inlet 4 from the well (not shown) has a high pressure. When the fluid passes through the restrictive cage ports 16, it undergoes a considerable pressure drop. Thus, the fluid passing through the cage bore 17 and the valve body outlet 5 is at a lower pressure than that in the body inlet 4.
When the flow trim 10 becomes worn beyond its useful service life due to erosion and corrosion caused by particles and corrosive agents in the produced substances, an ROV is used to approach the choke valve 1, unclamp the insert assembly 7 from the choke valve body 2 and attach a cable to the insert assembly 7, so that it may be raised to the surface for replacement or repair. The ROV then installs a new insert assembly 7 and clamps it into position. This procedure eliminates the need to raise the whole wellhead assembly to the surface to service a worn choke valve.
In order to efficiently produce a reservoir, it is necessary to monitor the flow rate of the production fluid. This is done to ensure that damage to the formation does not occur and to ensure that well production is maximized. This process has been, historically, accomplished through the installation of pressure and temperature transmitters into the flow lines upstream and downstream of the choke valve. The sensor information is then sent to a remote location for monitoring, so that a choke valve controller can remotely bias the flow trim to affect the desired flow rate. The controller sends electrical signals to means, associated with the choke valve, for adjusting the flow trim.
A problem exists with this process due to the unreliable nature of these electronic sensors, which have a limited service life. Replacing the sensors after they have served their useful life has heretofore required that the whole wellhead assembly be raised to the surface. This is a time-consuming and costly operation that shuts down well production for the duration of the repair.
When dealing with 100 percent liquid flow upstream and downstream pressure data, combined with a calibrated choke valve is sufficient to determine flow rate. This is not the case when considering gaseous production fluids. Due to the highly compressible nature of gasses, temperature data is also required in order to determine the production flow rate. Currently, temperature sensors and transmitters for sub-sea choke valves are located somewhat distant (i.e., upstream and/or downstream) of the choke valve itself. U.S. Pat. No. 6,460,621, issued Oct. 8, 2002 to Fenton et al., describes a sub-sea wellhead which uses pressure and temperature sensors located upstream and downstream of the choke valve.
U.S. patent application Ser. No. 10/060,559/published as 2003/0141072 on Jul. 31, 2003, and assigned to Master Flo Valve Inc., describes a sub-sea choke valve with pressure transmitters. As indicated above, it is advantageous to also measure temperature at the choke valve in order to calculate the flow rate when considering gas flows.
There is still a need for a choke valve that eliminates the need to raise the sub-sea wellhead assembly to the surface to replace or repair temperature transmitters.